Advanced BioFuels USA

by Jason Deign (GreenTechMedia) … According to the nomenclature used by market research firm Wood Mackenzie, most of the gas that is already widely used as an industrial chemical is either brown, if it’s made through the gasification of coal or lignite; or gray, if it is made through steam methane reformation, which typically uses natural gas as the feedstock. Neither of these processes is exactly carbon-friendly.

A purportedly cleaner option is known as blue hydrogen, where the gas is produced by steam methane reformation but the emissions are curtailed using carbon capture and storage. This process could roughly halve the amount of carbon produced, but it’s still far from emissions-free.

Green hydrogen, in contrast, could almost eliminate emissions by using renewable energy — increasingly abundant and often generated at less-than-ideal times — to power the electrolysis of water.

A more recent addition to the hydrogen-production palette is turquoise. This is produced by breaking methane down into hydrogen and solid carbon using a process called pyrolysis. Turquoise hydrogen might seem relatively low in terms of emissions because the carbon can either be buried or used for industrial processes such as steelmaking or battery manufacturing, so it doesn’t escape into the atmosphere.

However, recent research shows turquoise hydrogen is actually likely to be no more carbon-free than the blue variety, owing to emissions from the natural-gas supplies and process heat required.

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The challenge right now is that big electrolyzers are in short supply, and plentiful supplies of renewable electricity still come at a significant price. 

Compared to more established production processes, electrolysis is very expensive, so the market for electrolyzers has been small.

And while renewable energy production is now sizable enough to cause duck curves in California and grid problems in Germany, overproduction is a relatively recent development. Most energy markets still have a need for plenty of renewables just to serve the grid.

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How do you store and use this stuff?

Theoretically, there are lots of useful things you can do with green hydrogen. You can add it to natural gas and burn it in thermal power or district heating plants. You can use it as a precursor for other energy carriers, from ammonia to synthetic hydrocarbons, or to directly power fuel cells in cars and ships, for example.

To start with, you can use it simply to replace the industrial hydrogen that gets made every year from natural gas and which amounts to around 10 million metric tons in the U.S. alone.

The main problem with satisfying all these potential markets is in getting green hydrogen to where it is needed. Storing and transporting the highly flammable gas is not easy; it takes up a lot of space and has a habit of making steel pipes and welds brittle and prone to failure.

Because of this, the bulk transport of hydrogen will require dedicated pipelines, which would be costly to build, pressurizing the gas, or cooling it to a liquid. Those last two processes are energy-intensive and would further dent green hydrogen’s already underwhelming round-trip efficiency (see below).

Why is green hydrogen suddenly such a big deal?

One of the paths to near-total decarbonization is electrifying the whole energy system and using clean renewable power. But electrifying the entire energy system would be difficult, or at least much more expensive than combining renewable generation with low-carbon fuels. Green hydrogen is one of several potential low-carbon fuels that could take the place of today’s fossil hydrocarbons.

Admittedly, hydrogen is far from ideal as a fuel. Its low density makes it hard to store and move around. And its flammability can be a problem, as a Norwegian hydrogen filling station blast highlighted in June 2019.

But other low-carbon fuels have problems too, not least of which is cost. And since most of them require the production of green hydrogen as a precursor, why not just stick with the original product?

Proponents point out that hydrogen is already widely used by industry, so technical problems relating to storage and transport are not likely to be insurmountable. Plus, the gas is potentially very versatile, with possible applications in areas ranging from heating and long-term energy storage to transportation.

The opportunity for green hydrogen to be applied across a wide range of sectors means there is a correspondingly large number of companies that could benefit from a burgeoning hydrogen fuel economy. Of these, perhaps the most significant are the oil and gas firms that are increasingly facing calls to cut back on fossil fuel production.

Several oil majors are among the players jostling for pole position in green hydrogen development. Shell Nederland, for example, confirmed in May that it had joined forces with energy company Eneco to bid for capacity in the latest Dutch offshore wind tender so that it could create a record-breaking hydrogen cluster in the Netherlands. Days later, BP’s solar developer Lightsource BP revealed that it was mulling the development of an Australian green hydrogen plant powered by 1.5 gigawatts of wind and solar capacity.

Big Oil’s interest in green hydrogen could be critical in getting the fuel through to commercial viability. Cutting the cost of green hydrogen production will require massive investment and massive scale, something the oil majors are uniquely positioned to provide.

How much does green hydrogen cost to make?

Green hydrogen is still expensive to produce today. In a report published last year (using data from 2018), the International Energy Agency put the cost of green hydrogen at $3 to $7.50 per kilo, compared to $0.90 to $3.20 for production using steam methane reformation.

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The business case for green hydrogen requires very large amounts of cheap renewable electricity because a fair amount is lost in electrolysis. Electrolyzer efficiencies range from around 60 percent to 80 percent, according to Shell. The efficiency challenge is exacerbated by the fact that many applications may require green hydrogen to power a fuel cell, leading to further losses.

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More likely, as is already being considered by Lightsource BP and Shell, developers will build green hydrogen production plants with dedicated renewable energy generation assets in high-resource locations.

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But WoodMac forecasts output booming in the coming years. The pipeline of green hydrogen electrolyzer projects nearly tripled in the five months leading up to April 2020, to 8.2 gigawatts. The surge was mainly driven by an increase in large-scale electrolyzer deployments, with 17 projects scheduled to have 100 megawatts or more of capacity.

And it’s not simply the case that more projects are getting developed. By 2027, the average size of electrolyzer systems will likely exceed 600 megawatts, WoodMac says.

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Alongside oil and gas firms, renewable developers see green hydrogen as an emerging market, with offshore wind leader Ørsted last month trumpeting the first major project to exclusively target the transport sector.

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 But as the EV market has boomed, the prospect of hydrogen being a serious contender has faded from view, at least in the passenger vehicle segment.

There are roughly 7,600 hydrogen fuel-cell cars on U.S. roads today, compared to more than 326,400 plug-in electrics that were sold in the U.S. last year alone.

That said, pundits still expect hydrogen to play a role in decarbonizing some vehicle segments, with forklifts and heavy-duty trucks among those most likely to benefit.  READ MORE

Green hydrogen production: Landscape, projects and costs (Wood Mackenzie)

The future for green hydrogen  (Wood Mackenzie)

Could Full Decarbonization Depend on New Nuclear or CCS? Forecasts hint that achieving zero carbon will require at least one challenging technology. (GreenTechMedia)

Excerpt from GreenTechMedia:  Afry modeled two possible avenues to decarbonize Europe’s power, heat and transport sectors. One of them, called the “zero-carbon gas” pathway, involves using renewables along with other low-carbon technologies such biomethane, electrolysis, methane reforming, hybrid heat pumps and district heating to achieve deep cuts in energy system emissions.

The other, called “all-electric,” calls for the complete electrification of heat and transport, with no hydrogen or biomethane and a limit to biomass consumption. Both pathways can be used to achieve 100 percent decarbonization of the European energy system by 2050, Afry believes.

However, the all-electric pathway is €94 billion ($102 BILLION) more expensive PER YEAR by 2050, Afry estimates. This is mainly due to the cost of electrifying the heating and transport sectors, as well as a need to strengthen electricity networks to cope with much higher levels of utilization. (emphasis added)

The all-electric scenario also requires 190 gigawatts of new nuclear capacity to complement 1.1 terawatts of extra wind and 600 gigawatts of additional solar up until 2050.

The trouble is that the prospects for new nuclear in the European Union are not good. READ MORE